Wellbores for the oil and gas industry are commonly drilled by a process of rotary drilling. In conventional wellbore drilling, a drill bit is mounted on the end of a drill string, which may be several miles long. At the surface of the wellbore, a rotary table or top drive turns the drill string, including the drill bit arranged at the bottom of the hole to increasingly penetrate the subterranean formation, while drilling fluid is pumped through the drill string. In other drilling configurations, the drill bit may be rotated using a mud motor arranged axially adjacent the drill bit in the downhole environment and powered using the circulating drilling fluid.
One common type of drill bit used to drill wellbores is known as a “fixed cutter” or “drag” bit. A fixed cutter drill bit generally includes a bit body formed from a high strength material and a plurality of cutters attached at selected locations about the bit body. Cutters on fixed cutter drill bits often include a substrate or support stud made of carbide (e.g., tungsten carbide), and a cutting surface layer or “diamond table,” which can be made of polycrystalline diamond. Such cutters are commonly referred to as polycrystalline diamond compact (“PDC”) cutters.
Various methods for securing diamond materials to a substrate have been actively investigated. Often, diamond is simultaneously formed and bonded to a substrate using a single high-temperature, high-pressure (HTHP) press cycle. However, this method conventionally uses a so-called catalyzing material, such as cobalt, to facilitate bonding between the diamond particles and between the as-formed diamond and the substrate. The presence of residual catalyzing material in the diamond can result in reduced thermal stability, so PDC cutters are often leached to remove residual cobalt from the working surface. In other cases, instead of attaching the diamond to the substrate in the press, PDC may first be formed and then attached to the substrate, such as by brazing using an active metal braze alloy.